Additives to enhance phosphorus compound removal in refinery desalting processes

ABSTRACT

Reactive phosphorus species can be removed or transferred from a hydrocarbon phase to a water phase in an emulsion breaking process by using a composition that contains water-soluble hydroxyacids. Suitable water-soluble hydroxy-acids include, but are not necessarily limited to glycolic acid, gluconic acid, C 2 -C 4  alpha-hydroxy acids, poly-hydroxy carboxylic acids, thioglycolic acid, chloroacetic acid, polymeric forms of the above hydroxyacids, poly-glycolic esters, glycolate ethers, and ammonium salt and alkali metal salts of these hydroxyacids, and mixtures thereof. The composition may optionally include a mineral acid to reduce the pH of the desalter wash water. A solvent may be optionally included in the composition. The invention permits transfer of reactive phosphorus species into the aqueous phase with little or no hydrocarbon phase undercarry into the aqueous phase. The composition is particularly useful in treating crude oil emulsions, and in removing calcium and other metals therefrom.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part application from U.S. patentapplication Ser. No. 10/649,921 filed Aug. 27, 2003 that claims thebenefit of U.S. Provisional Application No. 60/407,139 filed Aug. 30,2002.

FIELD OF THE INVENTION

The present invention relates to methods and compositions for separatingemulsions of hydrocarbons and water, and more particularly relates, inone embodiment, to methods and compositions for transferring reactivephosphorus species to an aqueous phase in an emulsion breaking process.

BACKGROUND OF THE INVENTION

In an oil refinery, the desalting of crude oil has been practiced formany years. The crude is usually contaminated from several sources,including, but not necessarily limited to:

-   -   Brine contamination in the crude oil as a result of the brine        associated with the oil in the ground;    -   Minerals, clay, silt, and sand from the formation around the oil        well bore;    -   Metals including calcium, zinc, silicon, nickel, sodium,        potassium, etc.;    -   Nitrogen-containing compounds such as amines used to scrub H₂S        from refinery gas streams in amine units, or from amines used as        neutralizers in crude unit overhead systems, and also from H₂S        scavengers used in the oilfield;    -   Iron sulfides and iron oxides resulting from pipeline and vessel        corrosion during production, transport, and storage; and    -   Reactive phosphorus species that may result from gel compounds        used in oil well stimulation.

Desalting is necessary prior to further processing to remove thesecompounds and other inorganic materials that would otherwise causefouling and deposits in downstream heat exchanger equipment and/or formcorrosive salts detrimental to crude oil processing equipment. Further,these phosphorus compounds and metals can act as poisons for thecatalysts used in downstream refinery units. Effective crude oildesalting can help minimize the effects of these contaminants on thecrude unit and downstream operations. Proper desalter operations providethe following benefits to the refiner:

-   -   Reduced crude unit corrosion.    -   Reduced crude preheat system fouling.    -   Reduced potential for distillation column damage.    -   Reduced energy costs.    -   Reduced downstream process and product contamination.

Desalting is the resolution of the natural emulsion of water thataccompanies the crude oil by creating another emulsion in which about 5percent relative wash water is dispersed into the oil using a mix valve.The emulsion mix is directed into a desalter vessel containing aparallel series of electrically charged plates. Under this arrangement,the oil and water emulsion is exposed to the applied electrical field.An induced dipole is formed on each water droplet within the emulsionthat causes electrostatic attraction and coalescence of the waterdroplets into larger and larger droplets. Eventually, the emulsionresolves into two separate phases—the oil phase (top layer) and thewater phase (bottom layer). The streams of desalted crude oil andeffluent water are separately discharged from the desalter.

The entire desalting process is a continuous flow procedure as opposedto a batch process. Normally, chemical additives are injected before themix valve to help resolve the oil/water emulsion in addition to the useof electrostatic coalescence. These additives effectively allow smallwater droplets to more easily coalesce by lowering the oil/waterinterfacial tension.

Crude oil that contains a high percent of particulate solids cancomplicate the desalting process. The particulate solids, by nature,would prefer to transfer to the water phase. However, much of the solidsin a crude oil from a field exists in tight water-in-oil emulsions. Thatis, oil-wetted solids in high concentration in the crude may help formtight oil and water emulsions that are difficult to resolve. These tightemulsions are often referred to as “rag” and may exist as a layerbetween the separated oil and water phases. The rag layer inside thedesalter vessel may grow to such an extent that some of it will beinadvertently discharged with the water phase. This is a problem for thewaste water treatment plant since the rag layer still contains a highpercentage of unresolved emulsified oil.

As mentioned, much of the solids encountered during crude oil desaltingconsists commonly as particulates such as iron oxide, iron sulfide,sand, clay and even phosphorus-containing compounds, etc. Other metalsthat are desirably removed include, but are not necessarily limited to,calcium, zinc, silicon, nickel, sodium, potassium, and the like, andtypically a number of these metals are present. Some of the materialsmay be present in a soluble form, and some may require modificationthrough reaction such as hydrolysis or neutralization to become soluble.The metals may be present in inorganic or organic forms. In addition tocomplicating the desalter operation, phosphorus and other contaminantsare of particular concern to further downstream processing. Thisincludes the coking operation since iron and other metals remaining inthe processed hydrocarbon yields a lower grade of coke. Removing themetals from the crude oil early in the hydrocarbon processing stages isdesired to eventually yield high quality coke as well as to limitcorrosion and fouling processing problems.

Several treatment approaches have been made to reduce total contaminantlevels and these all center on the removal of contaminants at thedesalter unit. Normally, the desalter only removes water solubleinorganic salts such as sodium or potassium chlorides. Some crude oilscontain water insoluble forms of phosphorus, which are soluble ordispersed as fine particulate matter in the oil but not in water.

Additionally, many refineries in Canada and the northern US haveexperienced fouling of tower trays with deposits that have been analyzedto contain phosphorus. In one non-limiting theory, the source of thesephosphorus deposits may be gel compounds used in oil well stimulation.

It would thus be desirable to develop a composition and method employingit that would cause most or all of reactive phosphorus species in thecrude oil to transfer from the oil phase in a desalter operation, withlittle or no oil carryunder in the aqueous phase. Nonyl phenol resinshave been used as desalting additives in the past, but these materialshave come under suspicion as possible hormonal mimics and areineffective by themselves of removing metals such as calcium or iron.

SUMMARY OF THE INVENTION

Accordingly, it is an object of the present invention to provide acomposition and method of using it that would transfer a large part ofthe reactive phosphorus species in the crude oil to the aqueous phase ina desalter operation.

It is another object of the present invention to provide a compositionand method for transferring reactive phosphorus species from ahydrocarbon into an aqueous phase in an emulsion breaking operationwithout causing oil undercarry into the aqueous phase.

In carrying out these and other objects of the invention, there isprovided, in one form, a method of transferring at least a portion ofone or more reactive phosphorus species from a hydrocarbon phase to awater phase involving adding to an emulsion of hydrocarbon and water, aneffective amount of a composition to transfer the reactive phosphorusspecies from a hydrocarbon phase to a water phase containing at leastone water-soluble hydroxyacid. The water-soluble hydroxyacid may beglycolic acid, gluconic acid, C₂-C₄ alpha-hydroxy acids, poly-hydroxycarboxylic acids, thioglycolic acid, chloroacetic acid, polymeric formsof the above hydroxyacids, poly-glycolic esters, glycolate ethers, andammonium salt and alkali metal salts of these hydroxyacids, and mixturesthereof. The emulsion is then resolved into hydrocarbon phase and anaqueous phase, where at least a portion of the reactive phosphorusspecies have been transferred to the aqueous phase. This is accomplishedby converting the water insoluble salt such as calcium naphthenate intoa water soluble salt such as calcium glycolate.

In another non-limiting embodiment of the invention, there is provided acomposition for transferring at least a portion of one or more reactivephosphorus species from a hydrocarbon phase to a water phase thatincludes a water-soluble hydroxyacid (as defined above, including thesalts thereof), and a mineral acid.

There is provided in another non-limiting embodiment of the invention acomposition for transferring at least a portion of reactive phosphorusspecies from a hydrocarbon phase to a water phase that includes awater-soluble hydroxyacid (as defined above, including the saltsthereof) and at least one additional component that may be a hydrocarbonsolvent, a corrosion inhibitor, a demulsifier, a scale inhibitor, metalchelants, wetting agents and mixtures thereof.

In still another non-limiting embodiment of the invention, there isprovided a treated hydrocarbon emulsion that includes a hydrocarbonphase, a water phase, and a composition for transferring at least aportion of one or more reactive phosphorus species from the hydrocarbonphase to the water phase comprising a water-soluble hydroxyacid (asdefined above, including the salts thereof).

BRIEF DESCRIPTION OF THE DRAWING

The FIGURE is a graph of various amines and ammonia partitioning acrossdesalters as a function of pH.

DETAILED DESCRIPTION OF THE INVENTION

The inventors have discovered that the addition of glycolic acid(hydroxy-acetic acid) and other water-soluble hydroxyacids to a crudeoil can significantly reduce the amount of calcium and other metalsand/or amines as well as reactive phosphorus species in the hydrocarbonwhen it is run through a desalter in a refinery. The inventors havecompared the “normal” desalting on a reference crude oil containinghigher than normal amounts of calcium and found minimal calcium removal.The addition of glycolic acid in levels of up to a 5:1 ratio withcalcium, results in much lower metals and/or amine content of thedesalted oil. The levels of metals other than calcium such as iron,zinc, silicon, nickel, sodium and potassium are also reduced. Theremoval of particulate iron in the form of iron oxide, iron sulfide,etc. is a specific, non-limiting embodiment of the invention. By“removing” the metals and/or amines or reactive phosphorus species fromthe hydrocarbon or crude is meant any and all partitioning,sequestering, separating, transferring, eliminating, dividing, removing,of one or more metal or phosphorus species from the hydrocarbon or crudeto any extent.

It has been discovered that the phosphorus-containing salts that formfouling deposits on the trays of refineries may be made by mixing alkylphosphate esters with aluminum-containing compounds. The reaction formsa three-dimensional structure that is a basis of the gels used in oilwell stimulation.

Addition of hydroxyacids such as glycolic acid will help in thehydrolysis of phosphate ester gelling compounds since esters are knownto be hydrolyzed by acid catalysts and/or species. This reaction isfurther promoted by temperatures above about 180° F. (about 82° C.),alternatively about 200° F. (about 93° C). Thus, the addition ofglycolic acid and the like into desalter wash water and heating aboveabout 212° F. (about 100° C.) should promote the hydrolysis of phosphateesters and the like. Once hydrolyzed, the phosphate should be watersoluble and can be removed in the desalter effluent water.

In particular, and not wishing to be limited to any particular theory,since the gel-forming compounds are alkyl phosphate esters, it isbelieved that contacting the crude oil or other hydrocarbon containingthem with water acidified with a hydroxyacid, e.g. glycolic acid, at atemperature of from about 180° F. (about 82° C.) to about 350° F. (about177° C.) will hydrolyze the ester bonds and/or extract aluminum awayfrom the phosphorus. The resulting molecules will be phosphate orphosphoric acid which will dissolve in the wash water and/or organicalcohols that dissolve in oil or water depending on their molecularweight and polarity. Thus, the phosphorus will be removed from thehydrocarbon and reduce downstream fouling.

Being an aqueous additive, the glycolic acid is typically added to thewash water in the desalter. This improves distribution of the acid inthe oil although addition to the aqueous phase should not be viewed as arequirement for the composition of the invention to work.

The composition and method of the invention will be valuable to producehigh quality (i.e., high purity) coke from crude that may originallyhave contained high concentrations of metals and/or amines and solidsand/or reactive phosphorus species, including iron-based solids.Further, the invention advances the technology by removing inorganicmaterial from the crude oil without discharging any oil or emulsion tothe waste treatment plant.

In this invention, it will be understood that the metals include, butare not necessarily limited to, those of Groups IA, IIA, VB, VIIB, VII,IIB, IVA and VA of the Periodic Table (CAS version). In anothernon-limiting embodiment, the metals include, but are not necessarilylimited to calcium, iron, zinc, silicon, nickel, sodium, potassium,vanadium, mercury, manganese, barium, zinc, aluminum, copper,phosphorus, and combinations thereof. It is realized that phosphorus isnot strictly a metal, but phosphorus compounds and species arenevertheless removed by this process. In particular, nickel and vanadiumare known poisons for catalysts used in fluid catalytic cracking units(FCCUs) downstream.

The amines removed in accordance with the method of this invention mayinclude, but are not necessarily limited to, monoethanolamine (MEA);diethanolamine (DEA); triethanolamine (TEA); N-methylethanolamine;N,N-dimethylethanolamine (DMEA); morpholine; N-methyl morpholine;ethylenediamine (EDA); methoxypropylamine (MOPA); N-ethyl morpholine(EMO); N-methyl ethanolamine, N-methyldiethanolamine and combinationsthereof.

In one embodiment of the invention, the composition of the inventionincludes a water-soluble hydroxy acid. Hydroxy acids are defined hereinas not including or exclusive of acetic acid. Acetic acid has sometimesbeen used to remove metals as well, but it has a high oil solubility andtends to stay with the hydrocarbon coming from the desalter. The acidityof the acetic acid can then cause corrosion problems in the crude unit.The water-soluble hydroxy acids are much more water-soluble and will notpartition as much into the crude oil, thus reducing downstream concerns.They are also less volatile and do not distill into the crude unitoverhead system where they can increase corrosion rates when combinedwith the water usually present at this location.

In one preferred, non-limiting embodiment of the invention, thewater-soluble hydroxyacid is selected from the group consisting ofglycolic acid, C₁-C₄ alpha-hydroxy acids, poly-hydroxy carboxylic acids,thioglycolic acid, chloroacetic acid, polymeric forms of the abovehydroxyacids, glycolate ethers, poly-glycolic esters, and mixturesthereof. While thioglycolic acid and chloroacetic acid are not strictlyspeaking hydroxyacids, they are functional equivalents thereof. For thepurposes of this invention, they are defined as hydroxyacids. The alphasubstituent on the C₁-C₄ alpha-hydroxy acids may be any C₁-C₄ straightor branched alkyl group. In one non-limiting embodiment of theinvention, the alpha substituent may be C₂-C₄ straight or branched alkylgroup and lactic acid is not included. Gluconic acid, CH₂OH(CHOH)₄COOH,is a non-limiting but preferred polymer or oligomer of glycolic acid.The glycolate ethers may have the formula:

where n ranges from 1-10. The glycolate esters may have a formula:

where n is as above. Thioglycolic acid and the ethers of glycolic acidmay have the added benefits of a higher boiling point, and possiblyincreased water solubility. A higher boiling point means the additivewill not distill into the distillate fractions in the crude unit andcause corrosion or product quality concerns. The higher water solubilityalso favors removal of the additive from the crude in the desalter andreduces the amount that may reach the downstream processing units.

In particular, the definition of water-soluble hydroxyacids includesammonium salt and alkali metal salts (e.g. sodium and potassium salts,etc.) of these hydroxyacids alone or in combination with the otherwater-soluble hydroxyacids mentioned. Such salts would be formed in thedesalter wash water as the system's pH was adjusted with pH adjusterssuch as sodium hydroxide, potassium hydroxide, ammonia, and the like.

In another non-limiting embodiment the water-soluble hydroxyacids do notinclude citric acid, malic acid, tartaric acid, mandelic acid, andlactic acid. In yet another non-limiting embodiment of the invention,the definition of water-soluble hydroxyacids does not include organicacid anhydrides, particularly acetic, propionic, butyric, valeric,stearic, phthalic and benzoic anhydrides.

In yet another non-limiting embodiment of the invention, glycolic acidand gluconic acid may be used to remove calcium and amines, andphosphorus-containing species and thioglycolic acid may be used for ironremoval, from crude oil or another hydrocarbon phase.

It is expected that the water-soluble hydroxyacids will be used togetherwith other additives including, but not necessarily limited to,corrosion inhibitors, demulsifiers, pH adjusters, metal chelants, scaleinhibitors, hydrocarbon solvents, and mixtures thereof, in a commercialprocess. Metal chelants are compounds that complex with metals to formchelates. In particular, mineral acids may be used since metal removalis best accomplished at an acidic pH. The use of combinations ofwater-soluble hydroxyacids, particularly glycolic acid or gluconic acid,and mineral acids may give the best economics in a commercialapplication. Suitable mineral acids for use in conjunction with thewater-soluble hydroxyacids of this invention include, but are notnecessarily limited to, sulfuric acid, hydrochloric acid, phosphoricacid, nitric acid, phosphorous acid, and mixtures thereof. As noted, inone embodiment of the invention, the method of this invention ispracticed in a refinery desalting process that involves washing thecrude emulsion with wash water. In one non-limiting embodiment of theinvention, the amount of mineral acid used may be sufficient to lowerthe pH of the wash water to 6 or below. As noted below, in someembodiments of the invention, it may be necessary or preferred to lowerthe pH of the wash water to 5 or below, alternatively to 4 or below. Thewater-soluble hydroxyacids (and salts thereof) are expected to be usefulover a wide pH range, although in some situations it may be necessary ordesirable to adjust the pH to achieve the desired contaminant transferor separation.

It will be appreciated that the necessary, effective or desiredproportions of the hydroxyacid and/or the mineral acid will be difficultto predict in advance, since these proportions or dosages are dependentupon a number of factors, including, but not necessarily limited to, thenature of the hydrocarbon, the concentration of metal species,phosphorus species and/or amine to be removed, the temperature andpressure conditions of method, the particular hydroxyacid and mineralacid used, etc. In general, the more of a species, such as calcium,there is to be removed, the more of the reactive acid that must beadded. Since many undesirable species are affected, a successful metalor phosphorus removal process may require more reactive acid on astoichiometric basis than would be indicated by the concentration ofonly the target species. It may therefore be insufficient to only justadd enough acid to get the pH below 6. Nevertheless, in order to givesome sense of the proportions that may be used, in one non-limitingembodiment of the invention, the composition may comprise down to about1 wt. % water-soluble hydroxy-acid; and up to about 20 wt. % mineralacid, preferably from about 1 to about 100 wt. % water-solublehydroxyacid; and from about 1 to about 20 wt. % mineral acid, and mostpreferably from about 25 to about 85 wt. % water-soluble hydroxyacid;and from about 15 to about 75 wt. % mineral acid. In some non-limitingembodiments of the invention, the mineral acid is optional and may beomitted. In some non-limiting embodiments there may be limits to theamount of mineral acid added. In some cases it has been found that usingmineral acid only, the breaking of the emulsion is made more difficult.In other non-restrictive cases, there may be danger of forming scalessuch as calcium phosphate or calcium sulfate with the use of mineralacids.

The additive blend of this invention is injected into the wash waterbefore the mix valve in neat form or diluted with water, alcohol orsimilar solvent suitable to keep all additive components in solution.The amount of solvent used may range from about 10 to about 95 wt. %,based on the total composition, preferably from about 20 to about 10 wt.%.

The concentration of the additive blend composition of this invention tobe used in the crude oil to be effective is very difficult to predict inadvance since it depends on multiple, interrelated factors including,but not limited to, the composition of the crude, the desaltingconditions (temperature, pressure, etc.), the flow rate of the crude andits residence time in the desalter, among others. Nevertheless, for thepurposes of non-limiting illustration, the proportion of the activewater-soluble hydroxyacid that may be used in the crude (not includingany solvent or mineral acid) may range from about 1 to about 10,000ppm-w, alternatively from about 1 to about 2000 ppm-w, and in anothernon-limiting embodiment from about 10 to about 500 ppm-w and will dependon the concentration of metal species to be removed. In the treatment ofslop oil to remove metal species with the methods and compositionsherein, it may be necessary to use very high dosages on the order ofabout 1 to about 10 wt %. It is anticipated that in some non-restrictiveembodiments, the compositions and methods herein may be applied to wasteoils such as lubricating oils and crankcase oils, in other non-limitingembodiments. The organic hydroxy acid reacts stoichiometrically with theorgano metal and/or amine species to be removed. Thus an equivalentamount of organic hydroxy acid must be added compared to theconcentration of metal species to be removed. A slight excess of theacid will ensure that the reaction goes to completion. In onenon-limiting embodiment of the invention, the amount of water-solublehydroxyacid is stoichiometric with the amount of metals and/or aminespresent, or greater than stoichiometric. For economic reasons therefinery may chose to leave some of the metal, phosphorus and/or aminespecies in the crude at an acceptably low level of contamination ofhydrocarbon. In those cases the treatment level of the hydroxy acids canbe correspondingly reduced.

It is most preferred, of course, that in the practice of this inventionthere be no oil carryunder in the aqueous phase, and that at least oilcarryunder is minimized. Further, while it is preferred that all of themetals, phosphorus species and/or amines transfer to the aqueous phase,in one non-limiting theory of the invention, some of the metals and/oramines may be transferred from the oil phase into the rag. Thisproportion of metals and/or amines is then removed when the rag iscleaned out.

It is also most preferred, of course, that in the practice of thisinvention all of the metals, phosphorus species and/or amines transferto the aqueous phase. In another non-limiting embodiment of theinvention, 25% or less metal, phosphorus species and/or amine is presentin the hydrocarbon phase after desalting, preferably 20% or less metal,phosphorus species and/or amine remains, most preferably only 10% orless remains. In some cases the refinery may chose to leave higherpercentages of metal, phosphorus species and/or amine contaminants inthe crude if the detrimental effects are judged to be economicallyacceptable.

The invention will be illustrated further with reference to thefollowing Examples, which are not intended to limit the invention, butinstead illuminate it further.

The following Electrostatic Desalting Dehydration Apparatus (EDDA) TestMethod was employed to screen possible blend compositions. The EDDA is alaboratory test device to simulate the desalting process.

EDDA Test Method

1. Add 800, 600 or 400 ml of crude oil to be tested minus the percent ofwash water (depending on the number of tubes the EDDA will hold) to aWaring blender.

2. Add the required percentage of wash water to the blender to bring thetotal volume up to 800, 600 or 400 ml.

3. Mix at 50% speed (on the Variac) for 30 seconds. The speed can bereduced if the ΔP on the mix valve is low.

4. Pour the mixture into the EDDA tubes to just below the 100 ml line.

5. Place the tubes in the EDDA heating block that is at the desired testtemperature (99° C).

6. Add the desired quantity of demulsifier, in ppm, to each tube. Withevery test, a blank must be run for comparison purposes.

7. Place the screw top electrode in the tubes and allow the samples toheat for approximately 15 minutes.

8. Tighten the caps and shake each tube 100-200 times and place back inthe heating block to reheat for five minutes.

9. Place the electrode cover over the tubes and lock into place. Makesure that there is good contact between the cover and the electrodecaps.

10. Set the time for five minutes and run at 1500-3000 volts, dependingon the test requirements.

11. At the end of the five minutes, pull the tubes out and check for thepercent water drop. Also check the quality of the interface and thequality of the water and record it.

12. Repeat steps 9, 10, and 11 until the desired total residence time isachieved.

13. Determine the best candidates and run a dehydration test on thosesamples.

-   -   a) Fill the desired number of 12.5 ml centrifuge tubes to the        50% mark with xylene.    -   b) Use a glass syringe to pull 5.8 ml of dehydrated crude sample        from the desired level in the tube and mix in with the xylene in        the centrifuge tubes.    -   c) Centrifuge the tubes at 2000 rpm for 4 minutes.    -   d) Check for the quantity of water, emulsion, and solids that        are present in the bottom of the tube and record.        Analysis for Calcium

After completing the EDDA test, use a glass syringe and cannula (long,wide bore needle), to withdraw two 20 ml aliquots of the EDDA desaltedcrude oil. Abstract the oil at a level in the EDDA tube that is at 25 mland 70 ml below the surface of the oil. The two samples (top cut andbottom cut) are each analyzed for calcium concentration by whateverappropriate method (wet ash or microwave digestion, acidification,dilution, AA or ICP analysis). A similar procedure would be used togenerate oil and water samples that could be analyzed by ionchromatography for other contaminants such as amine salts and reactivephosphorus species.

The crude oil used was from an African country that has a high calciumcontent.

-   -   Additive A=70% glycolic acid, balance water.

Additive B=A blend of glycolic acid, phosphoric acid (pH adjuster), apyridine quaternary ammonium compound (corrosion inhibitor), a dinonylphenol/ethylene oxide oxyalkylate (co-solvent), isopropyl alcohol andwater. TABLE I Sample A - 100% Crude Desalted Crude Oil* Raw Top WaterCrude Phase, Interface, Phase, Ex. Metal Additive Oil, ppm ppm ppm ppm 1Calcium A 370 30 31 1700 2 ″ B 370 76 76 1210 3 Iron A 60 14 15 113 4 ″B 60 26 27 8 5 Zinc A 35 6 4 163 6 ″ B 35 17 16 34 7 Silicon A 37 <2 <26 8 ″ B 37 <2 2 7 9 Nickel A 8 9 9 <2 10 ″ B 8 9 10 <2 11 Sodium A 97 910 416 12 ″ B 97 13 12 404 13 Potassium A 789 31 32 4030 14 ″ B 789 3432 3900*Top Phase = 20 mL sample taken at 75 mL mark of 100 mL EDDA test tube.Interface = 20 mL oil sample taken near oil/water interface present inEDDA test tube.

TABLE II Sample B - 20% High Calcium Crude Blend Desalted Crude Oil RawTop Water Addi- Crude Phase, Interface, Phase, Ex. Metal tive Oil, ppmppm ppm ppm 15 Calcium A Emulsion Emulsion Emulsion Emulsion 16 ″ B 58 8  5 362  17 Iron A Emulsion Emulsion Emulsion Emulsion 18 ″ B 10  2 <2  3.6 19 Zinc A Emulsion Emulsion Emulsion Emulsion 20 ″ B  6  5 22 3221 Silicon A Emulsion Emulsion Emulsion Emulsion 22 ″ B <2 11 20  2 23Nickel A Emulsion Emulsion Emulsion Emulsion 24 ″ B  2  3  3 <2 25Sodium A Emulsion Emulsion Emulsion Emulsion 26 ″ B 17 15  8 113  27Potassium A Emulsion Emulsion Emulsion Emulsion 28 ″ B 79  3  4 91

From the data presented above it may be seen that the water-solublehydroxyacid used (glycolic acid) effectively removed or transferred avariety of metals from the oil phase to the water phase. The inventivemethod was particularly effective on the high content metals such ascalcium and potassium.

Tables III-VI provide additional data showing the transfer of variousmetals from a hydrocarbon phase to a water phase using the water-solublehydroxy-acids of the invention. The various components are defined asfollows (all proportions are volume percents):

-   -   Additive C 70% glycolic acid, 30% water    -   Additive D 75% Additive C, 20% acrylic acid polymer scale        inhibitor (which alone is designated SI1), 1.8% alkyl pyridine        quaternary ammonium salt corrosion inhibitor, and 3.2%        oxyalkylated alkyl phenol surfactant    -   Additive E 72% phosphorous acid scale control/pH adjuster        compound, 14% oxyalkylated polyalkyleneamine, and 14% SI1.    -   Additive F 10% oxalic acid, 20% thioglycolic acid, 10% glycolic        acid, 1.5% alkyl pyridine quaternary ammonium salt corrosion        inhibitor, and 58.5% water.    -   DA through DF designate Demulsifiers A through F, which are all        various oxyalkylated alkylphenol resin demulsifiers. When used        together with an additive of this invention, they may be        abbreviated such as DA/D which indicates Demulsifier A is used        together with Additive D in the ppm ratio given in the next        column.    -   SI2 Scale Inhibitor 2 that contains diammonium ethylenediamine        tetracetic acid (EDTA).    -   SI3 Scale Inhibitor 3 that contains an amine phosphonate scale        inhibitor.

SRA1 Scale Removal Additive 1, which is a blend of an alkyl pyridinequaternary ammonium salt corrosion inhibitor (same as in Additive D)with phosphoric acid, glycolic acid and a demulsifier. TABLE III EDDATest Results, Examples 29-40 Test Test Dose Metals Analysis Ex ConditionSample Additive (ppm) Na K Mg Ca 29 EDDA. Crude A C 1000 Top Oil 2.311.5 <1 85 10% DI (in water) Interface 2.5 8.5 <1 68 Wash Water Water443 4400 21.9 1560 30 EDDA. ″ lactic 1000 Top Oil 2.4 6.3 <1 37 10% DIacid (in water) Interface 1 6.5 <1 37 Wash Water Water 388 4170 22.11610 31 EDDA. ″ Blank none Oil 164 765 4 306 10% DI Wash Water 32 EDDA.″ C 2000 5 19 <3 24 10% DI (in water) 5 20 <3 24 Wash Water 425 4670 241640 33 Blank None Oil 87 919 5.8 363 34 EDDA. ″ SRA1 2000 Top Oil 13 3476 10% DI (in water) Interface 12 32 76 Wash Water Water 404 3900 211210 35 EDDA. ″ SI2 2000 Top Oil 11 14 192 10% DI (in water) Interface 710 191 Wash Water Water 414 4000 20 959 36 EDDA. ″ C 2000 Top Oil 9 3130 10% DI (in water) Interface 10 32 31 Wash Water Water 416 4030 221700 37 EDDA. ″ SI3 2000 Top Oil 15 60 276 10% DI (in water) Interface15 60 281 Wash Water Water 440 4190 538 38 EDDA. ″ Blank none Oil 97 7894 370 10% DI Wash Water 39 EDDA. ″ SRA1 2000 Top Oil 15 3 8 10% DI (inwater) Interface 8 4 5 Wash Water Water 113 91 6 362 40 EDDA. ″ Blanknone Oil 17 79 58 10% DI Wash Water Metals Analysis Ex Fe Cu Zn Al Sb BaV Pb Mn Ni Si P 29 51 <2 40.0 1.5 15 2.7 <1 8 10 10.0 1.3 8 40 <2 31.01.0 15 2.4 <1 8 8 8.0 <1 8 2.7 <0.1 3.7 0.3 <0.1 30.4 <0.1 0.6 18.2 0.25.5 <0.1 30 39 <2 30.0 1.2 14 2.4 <1 7 6 8.0 <1 7 38 <2 30.0 1.1 20 2.2<1 10 6 8.0 <1 11 5.5 <0.1 9.9 0.5 <0.1 32.3 <0.1 0.6 29.4 0.3 5.3 0.131 49 <2 30.0 8.0 14 8.5 <1 8 11 7.0 10 8 32 16 <0.5 2.0 1.2 <0.5 0.7<0.5 11.7 0.6 8.6 30.7 <2 16 <0.5 2.0 1.0 <0.5 0.7 <0.5 7.9 0.6 9.0 7.1<2 93.8 0.2 162.0 1.5 0.4 33.8 0.2 3.1 56.4 1.0 5.5 2.2 33 68.6 <0.532.0 11.4 <0.5 8.4 <0.5 6.8 12.2 8.4 15.6 2.8 34 26 17.0 2 93 3 9.0 8627 16.0 2 88 3 10.0 2 91 8 34.0 8 33 7 1300 35 29 7.0 6 80 12.0 45 9 282.0 5 84 9.0 2 6 82 164.0 11 4 58 6 36 14 6.0 94 9.0 5 15 4.0 86 9.0 4113 163.0 2.0 31 4 57 6 3 37 49 38.0 5 82 13 9.0 14 215 51 39.0 5 95 1310.0 7 223 13 7 50 38 60 35.0 8.0 8 48 13 8.0 37 3 39 2 5.0 73 3.0 11 1122.0 59 3.0 20 5 3.6 32.0 12 2 516 40 10 6.0 37 2.0

TABLE IV EDDA Test Results, Examples 41-54 Test Test Dose MetalsAnalysis Ex Condition Sample Additive (ppm) Na K Mg Ca 41 EDDA. Crude ADA 15 Top Oil 5.9 17.1 <3 371 10% DI WW Water 626 <5 17 210 42 EDDA. ″DB 15 Top Oil 5 13 <3 384 10% DI WW Water 705 <5 19 236 43 EDDA. ″ DC 15Top Oil 11 32 5 443 10% DI WW Water 579 <5 15 193 44 EDDA. ″ DD 15 TopOil 8 27 <3 368 10% DI WW Water 698 <5 17 234 45 EDDA. ″ DE 15 Top Oil 623 3 366 10% DI WW Water 612 <5 16 204 46 EDDA. ″ Blank None Oil 6 19 <3361 10% DI WW Water 650 <5 18 216 47 EDDA. Crude B DA 15 Top Oil 4 <5 <340 10% DI WW Water 147 950 7 143 48 EDDA. ″ DB 15 Top Oil 5 <5 <3 41 10%DI WW Water 134 882 6 129 49 EDDA. ″ DC 15 Top Oil 5 <5 <3 39 10% DI WWWater 147 948 7 140 50 EDDA. ″ DD 15 Top Oil 4 <5 <3 41 10% DI WW Water148 954 6 140 51 EDDA. ″ DE 15 6 <5 <3 46 8 10% DI WW 146 943 7 140 <0.252 EDDA. ″ Blank none Oil 5 <5 <3 48 10% DI WW Water 130 858 5 122 53EDDA. Crude C C 50 Top Oil 3 <1 <1 4 10% DI WW Interface 4 <1 <1 3 Water690 42 31 174 54 EDDA. ″ Bank none Oil 46 4 3 14 10% DI WW MetalsAnalysis Ex Fe Cu Zn Al Sb Ba V Pb Mn Ni Si P 41 58 <3 36.0 4.0 <3 5 <327 14 10.0 13 4 <0.2 <0.2 <0.2 <0.2 <0.2 7 <0.2 <0.4 <0.2 <0.2 10 <0.242 60 <3 36.0 5.0 <3 5 <3 22 14 10.0 9 3 <0.2 <0.2 <0.2 <0.2 <0.2 8 <0.2<0.4 <0.2 <0.2 10 <0.2 43 88 <3 38.0 41.0 <3 6 <3 33 14 11.0 55 3 <0.2<0.2 <0.2 <0.2 <0.2 7 <0.2 <0.4 <0.2 <0.2 8 <0.2 44 57 <3 36.0 4.0 <3 6<3 33 14 10.0 8 4 <0.2 <0.2 <0.2 <0.2 <0.2 9 <0.2 <0.4 <0.2 <0.2 9 <0.245 55 <3 35.0 4.0 <3 5 <3 21 14 10.0 66 <3 <0.2 <0.2 <0.2 <0.2 <0.2 8<0.2 <0.4 <0.2 <0.2 8 <0.2 46 54 <3 35.0 <3 <3 5 <3 20 13 9.0 8 3 <0.2<0.2 <0.2 <0.2 <0.2 8 <0.2 <0.4 <0.2 <0.2 9 <0.2 47 7 <3 6.0 <3 <3 <3 824 <3 <3 6 <3 <0.2 <0.2 <0.2 <0.2 <0.2 2 <0.2 <0.4 <0.2 <0.2 2 <0.2 48 6<3 6.0 <3 <3 <3 7 17 <3 <3 6 <3 <0.2 <0.2 <0.2 <0.2 <0.2 2 <0.2 <0.4<0.2 <0.2 2 <0.2 49 7 <3 6.0 <3 <3 <3 7 21 <3 <3 4 <3 <0.2 <0.2 <0.2<0.2 <0.2 1 <0.2 0.4 <0.2 <0.2 3 <0.2 50 6 <3 6.0 <3 <3 <3 7 21 <3 <3 3<3 <0.2 <0.2 <0.2 <0.2 <0.2 1 <0.2 <0.4 <0.2 <0.2 3 <0.2 51 <3 6.0 <3 <3<3 8 22 <3 <3 10 <3 <0.2 <0.2 <0.2 <0.2 1 <0.2 0.4 <0.2 <0.2 3 <0.2 52 6<3 6.0 <3 <3 <3 8 23 <3 <3 6 <3 <0.2 <0.2 <0.2 <0.2 <0.2 1 <0.2 0.5 <0.2<0.2 3 <0.2 53 2 <1 <1 1.0 <1 <1 12 <1 <1 6.0 3 3 5 <1 1.0 1.0 <1 <1 12<1 <1 6.0 3 3 124 <1 6.0 2.0 <1 2 <1 <1 <1 <1 2 2 54 22 <1 2.0 2.0 <1 <111 <1 <1 6.0 4 4

TABLE V EDDA Test Results, Examples 55-67 Test Test Dose Metals AnalysisEx Condition Sample Additive (ppm) Na K Mg Ca 55 EDDA. Crude DA/D 15/50Top Oil 6 29 3 225 4% DI WW D/G Blend Water 338 40 383 56 EDDA. CrudeDE/D 15/50 Top Oil 6 30 4 249 4% DI WW D/G Blend Water 341 34 388 57EDDA. Crude DB/D 15/50 Top Oil 11 76 4 244 4% DI WW D/G Blend Water 33435 375 58 EDDA. Crude DA/D 25/50 Top Oil 8 30 2 216 4% DI WW D/G BlendWater 339 39 382 59 EDDA. Crude DE/D 25/50 Top Oil 4% DI WW D/G BlendWater 338 37 380 60 EDDA. Crude DB/D 25/50 Top Oil 13 33 1 206 4% DI WWD/G Blend Water 345 37 386 61 EDDA. Crude Blank None Oil 44 930 11 2664% DI WW D/G Blend 62 EDDA. Crude DA/D 40/50 Top Oil 30 20 4 194 4% DIWW D/G Blend Water 155 18 142 63 EDDA. Crude DE/D 40/50 Top Oil 6 25 4205 4% DI WW D/G Blend Water 341 39 292 64 EDDA. Crude DB/D 40/50 TopOil 8 26 4 224 4% DI WW D/G Blend Water 336 34.2 287 65 EDDA. Crude DF/D40/50 Top Oil 8 43 6 230 4% DI WW D/G Blend Water 352 33.7 297 66 EDDA.Crude DD/D 40/50 Top Oil 8 67 8 250 4% DI WW D/G Blend Water 344 33 38667 EDDA. Crude DC/D 40/50 Top Oil 7 33 5 211 4% DI WW D/G Blend Water352 33.2 300 Metals Analysis Ex Fe Cu Zn Al Sb Ba V Pb Mn Ni Si P 55 293 15.0 4.0 5 11 8.0 2 11 0.2 <0.1 <0.1 <0.1 <0.1 17.5 1.1 <0.1 8.1 <0.156 32 4 15.0 3.0 5 12 10.0 3 <1 0.2 <0.1 <0.1 <0.1 <0.1 17.4 1.1 <0.17.1 <0.1 57 30 5 14.0 2.0 5 12 8.0 2 6 0.1 <0.1 <0.1 <0.1 <0.1 17.3 1.1<0.1 8 <0.1 58 26 7 15.0 3.0 5 11 7.0 <1 9 0.2 <0.1 <0.1 <0.1 <0.1 18.61.2 <0.1 9.6 <0.1 59 0.2 <0.1 <0.1 <0.1 <0.1 19 1.1 <0.1 8 <0.1 60 26 1415.0 2.0 5 10 6.0 1 8 0.3 <0.1 <0.1 <0.1 <0.1 19 1.2 <0.1 8.9 <0.1 61 332 15.0 4.0 7 11 6.0 3 9 62 29 4 12.0 4.0 3 4 9 3.0 5 14 <0.1 <0.1 <0.1<0.1 <0.1 6.8 0.6 <0.1 3.5 114 63 28 3 13.0 5.0 2 5 10 3.0 5 15 0.2 <0.1<0.1 <0.1 <0.1 13.6 1.1 <0.1 6.9 180 64 31 8 17.0 6.0 <1 5 10 5.0 2 180.2 <0.1 <0.1 0.2 <0.1 13.4 1.1 <0.1 7.1 180 65 36 4 19.0 11.0 <1 5 116.0 3 18 0.2 <0.1 <0.1 0.2 <0.1 13.6 1 <0.1 6.8 187 66 34 3 21.0 10.0 <16 12 8.0 4 27 0.2 <0.1 0.2 1.0 <0.1 13.4 1 <0.1 6.7 177 67 34 4 14.010.0 <1 5 10 4.0 4 14 0.2 <0.1 0.2 <0.5 <0.1 13.6 1.1 <0.1 6.7 183

TABLE VI EDDA Test Results, Examples 68-83 Test Test Dose MetalsAnalysis Ex Condition Sample Additive (ppm) Na K Mg Ca 68 EDDA. Crude EBlank None Oil 63 1590 12.2 475 7.5% DI WW 69 EDDA. ″ DA/E 30/70 Top Oil6.1 20.5 7.8 482 7.5% Water 212 2960 25 278 DI WW 70 EDDA. ″ DE/E 30/70Top Oil 5.6 17.7 7.4 435 7.5% Water 215 2990 27 281 DI WW 71 EDDA. ″DB/E 30/70 Top Oil 6 17.2 7.7 420 7.5% Water 218 3020 25.9 283 DI WW 72EDDA. ″ DF/E 30/70 Top Oil 6.2 19.6 7.5 485 7.5% Water 229 3140 29.2 298DI WW 73 EDDA. ″ DD/E 30/70 Top Oil 7 18.5 6.6 415 7.5% Water 230 316028.2 301 DI WW 74 EDDA. ″ DC/E 30/70 Top Oil 6 24.6 7.6 398 7.5% Water227 3170 28.1 293 DI WW 75 EDDA 5.0% Crude G acetic 1000 Top Oil <0.412.6 2.5 22.6 DI Wash W. acid (in water) Water 116 2430 56.1 3350 76EDDA 5.0% Crude F F 1000 Top Oil 0.8 7 3.9 190 DI Wash W. (in water)Water 113 2430 48.3 914 77 EDDA 5.0% Blend E Blank None Oil 11 320 3.3100 DI Wash W. 78 EDDA 5.0% +Other acetic 1000 Top Oil 1.4 7.7 1.2 21.5DI Wash W. Crude acid (in water) Water 146 3280 29.7 844 79 EDDA 5.0%30/70 F 1000 Top Oil 3 1.2 1 24.7 DI Wash W. Refinery (in water) Water140 3170 29.3 408 80 EDDA 5.0% Blend lactic 1000 Top Oil 2.5 25.6 1.332.2 DI Wash W. acid (in water) Water 121 2700 24.1 620 81 EDDA 5.0% ″glycolic 1000 Top Oil 2.4 22.9 1.2 25.9 DI Wash W. acid (in water) Water124 2830 25.2 700 82 EDDA 5.0% ″ SI1 1000 Top Oil 2 7.9 1.9 75 DI WashW. (in water) Water 958 3950 14.3 301 83 EDDA 5.0% ″ Oxalic 1000 Top Oil6.6 21.9 2.5 80 DI Wash W. acid (in water) Water 132 2970 20.38 87.4Metals Analysis Ex Fe Cu Zn Al Sb Ba V Pb Mn Ni Si P 68 23.8 0.5 13.00.6 <0.4 11 <0.4 <0.4 10.4 10.6 3.9 2.9 69 25 0.8 14.5 2.1 <0.4 9.2 <0.4<0.4 11.3 13.2 5.3 26.2 0.7 <0.1 0.1 4.0 <0.1 19.3 <0.4 <0.1 1.3 0.5 7.1291 70 25.2 0.6 14.7 0.5 <0.4 9.4 <0.4 <0.4 11.6 13.6 2.4 25.5 0.7 <0.1<0.1 0.1 <0.1 19.3 <0.4 <0.1 1.3 0.4 7.1 297 71 24 0.8 15.1 0.2 <0.4 8.6<0.4 <0.4 11.3 13.8 3.4 27.2 0.6 <0.1 <0.1 <0.1 <0.1 19.8 <0.4 <0.1 1.30.7 7.5 294 72 24.8 0.8 14.7 0.6 <0.4 9.4 <0.4 <0.4 11.4 14.2 2.6 25.30.6 0.2 <0.1 <0.1 <0.1 19.8 <0.4 <0.1 1.3 0.9 7.3 313 73 24.5 0.4 14.5<0.4 <0.4 8.9 <0.4 <0.4 11.3 13.6 3 26.6 0.6 <0.1 <0.1 <0.1 <0.1 20.1<0.4 <0.1 1.3 0.6 7.4 317 74 23.4 <0.4 15.0 <0.4 <0.4 8.4 <0.4 <0.4 10.914.8 4 29.2 0.7 <0.1 <0.1 <0.1 <0.1 20.3 <0.1 <0.1 1.4 0.8 7.8 302 7525.2 0.9 10.6 2.1 <0.4 0.6 <0.4 <0.4 2.5 11.6 1.1 4.2 72.1 0.5 43.9 <0.10.2 84.4 <0.1 0.2 126 0.5 5.4 0.3 76 31.8 0.7 15.2 3.0 <0.4 3.9 <0.4<0.4 12.8 11.7 2.4 4 4.6 <0.1 0.7 <0.1 <0.1 44.5 <0.1 <0.1 6.4 <0.1 6.10.1 77 11.3 0.4 4.2 1.1 <0.4 2.5 <0.4 <0.4 4.1 3.5 0.7 1.5 78 3.5 <0.413.8 9.9 <0.4 0.9 <0.1 <0.4 <0.4 4.1 1.3 2.2 96 0.2 44.9 0.2 <0.1 14.8<0.4 0.3 44.4 0.7 4 0.3 79 1.1 <0.4 0.6 1.0 <0.4 0.6 <0.1 <0.4 <0.4 4.0<0.4 2.1 118 <0.1 52.4 2.2 <0.1 4.2 <0.4 <0.1 38.8 0.5 4.9 0.6 80 2 0.61.1 1.0 <0.4 0.9 <0.1 <0.4 1.2 3.9 1.8 2 92.5 0.3 37.2 0.7 0.1 10.3 <0.40.7 25.8 36.3 5 0.7 81 2.7 <0.4 0.9 1.5 <0.4 0.8 <0.1 <0.4 1.1 3.9 2.62.2 92.2 0.3 38.2 0.6 0.2 9.8 <0.4 0.9 27.6 30.7 4.2 0.6 82 11.1 0.5 5.01.1 <0.4 1.7 <0.1 <0.4 4.2 3.8 <0.4 1.9 1.4 0.3 0.6 0.3 <0.1 12.6 <0.4<0.1 3.4 <0.1 5.4 0.1 83 11.4 0.5 4.7 1.0 <0.4 1.6 <0.1 <0.4 4.2 3.9<0.4 2.3 <0.1 <0.1 <0.1 <0.1 <0.1 5.2 <0.4 <0.1 0.7 <0.1 5 <0.1

EXAMPLES 84-110

Examples 84-110 were conducted using the same EDDA Test Method andanalytical method described above. All of the tests were conducted onthe same sample of crude oil. This sample of western Canadian crude oilwas from a refinery experiencing severing fouling with phosphorus-baseddeposits. The EDDA tests were run at 100° C. for all of the tests and5.5% wash water was used in each test. After the crude oil was treatedand processed in the EDDA, the effluent water was collected and sent foranalysis to determine the ion content in solution by ICP. The oilsamples were ashed using microwave digestion and the resulting aqueoussolution was analyzed by ICP. The various compositions tested are givenin Table VII. TABLE VII Additive Composition Additive G 98% glycolicacid (70%)  2% Magna 240 corrosion inhibitor available from BakerPetrolite Additive H 95% gluconic acid  5% citric acid Additive J 95%glycolic acid  4% thioglycolic acid Blend X Blend of non-ionic emulsionbreakers available from Baker Petrolite Blend Y Blend of non-ionicemulsion breakers available from Baker Petrolite

EXAMPLES 84-93

In these Examples, all samples were processed in the EDDA to simulate adesalting process. The first sample, Example 84, had no emulsion breakerof acid added, but was desalted. The rest of the samples except the washwater (Example 93) were treated with metals removal chemistry inaddition to an emulsion breaker to help resolve the emulsion. In thisstudy, Additive G at 20 ppm (Example 85) and in the other Examples 86,89 and 90 effectively removed Ca and Fe from the crude oil. Thetreatment also reduced P content by about 25%. TABLE VIII Ex. SampleIdentification 84 Raw crude (Blank sample) 85 Treat at 20 ppm ofAdditive G, Desalter crude 86 Treat at 30 ppm of Additive G, Desaltercrude 87 Treat at 30 ppm of Additive H, Desalter crude 88 Treat at 30ppm of Additive J, Desalter crude 89 Treat at 20 ppm of Additive G,Effluent water 90 Treat at 30 ppm of Additive G, Effluent water 91 Treatat 30 ppm of Additive H, Effluent water 92 Treat at 30 ppm of AdditiveJ, Effluent water 93 Wash water

TABLE IX ICP EDDA Test Results (ppm - wt/wt), Examples 84-93 Ex. Na K MgCa Mo Fe Cu Zn Al 84 73.5 4.7 6.8 33.8 <0.4 22.5 <0.4 2.0 <0.4 85 <0.40.6 0.9 0.6 <0.4 1.0 <0.4 1.1 <0.4 86 0.4 <0.4 0.9 0.9 <0.4 0.9 <0.4 1.0<0.4 87 0.5 0.4 1.0 1.3 <0.4 1.7 <0.4 1.7 <0.4 88 0.6 0.4 0.8 0.8 <0.41.7 <0.4 1.2 <0.4 89 1160 77.4 74.5 428 <0.1 30.0 0.8 7.0 <0.1 90 110075.5 71.2 407 <0.1 26.3 1.3 15.0 <0.1 91 1180 79.2 77.0 430 <0.1 43.00.4 5.5 <0.1 92 1230 82.3 79.4 450 <0.1 57.3 0.9 7.7 <0.1 93 11.8 2.619.0 60.2 0.1 4.7 <0.1 <0.1 <0.1 Ex. Ba Be Cd Cr Pb Mn Ni B 84 4.5 <0.4<0.4 <0.4 <0.4 <0.4 3.1 <0.4 85 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 2.9 <0.486 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.5 <0.4 87 <0.4 <0.4 <0.4 <0.4 <0.4<0.4 3.2 <0.4 88 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.2 <0.4 89 0.3 <0.1 <0.1<0.1 0.2 0.8 0.3 2.2 90 0.3 <0.1 <0.1 <0.1 0.5 0.8 0.5 2.1 91 0.4 <0.1<0.1 <0.1 0.1 0.9 0.3 2.2 92 0.3 <0.1 <0.1 <0.1 0.2 1.0 0.3 2.5 93 <0.1<0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 Ex. Sr Si P S Ti V Sn 84 1.1 5.6 4.3NR <0.4 6.9 <0.4 85 <0.4 0.5 3.0 NR <0.4 6.6 <0.4 86 <0.4 0.7 3.5 NR<0.4 7.6 <0.4 87 <0.4 0.7 3.4 NR <0.4 7.1 <0.4 88 <0.4 0.7 3.1 NR <0.47.1 <0.4 89 11.3 3.6 3.4 320 <0.1 <0.1 <0.1 90 10.7 3.4 3.2 310 <0.1<0.1 <0.1 91 11.6 4.0 4.5 340 <0.1 <0.1 <0.1 92 12.1 4.1 4.6 350 <0.1<0.1 <0.1 93 0.5 4.3 0.3 89.2 <0.1 <0.1 <0.1

EXAMPLE 94-95

In these Examples it may be seen that only 10 ppm of Additive G wasrequired to remove most of the Ca and Fe. Again, the P seems to bereduced by about 25%. TABLE X Ex. Sample Identification 94 Treat withBlend X @ 10 ppm-v Additive G @ 100 ppm-v Wash water rate 5.5% Mix ΔP =12 psig Effluent water 95 Treat with Blend Y @ 10 ppm-v Additive G @ 100ppm-v Wash water rate 5.5% Mix ΔP = 12 psig Desalter crude

TABLE XI ICP EDDA Test Results (ppm - wt/wt), Examples 94-95 Ex. Na K MgCa Mo Fe Cu Zn Al 94 1460 60.6 69.1 433 <0.1 76.3 2.8 8.7 1.8 95 <0.10.4 1.2 1.4 <0.1 2.0 <0.1 0.8 <0.1 Ex. Ba Be Cd Cr Pb Mn Ni B 94 0.2<0.1 <0.1 <0.1 0.4 0.9 0.3 2.0 95 <0.1 <0.1 <0.1 <0.1 0.5 <0.1 3.1 1.3Ex. Sr Si P S Ti V Sn 94 9.3 4.2 4.8 365 <0.1 <0.1 <0.1 95 <0.1 2.8 3.0NR <0.1 6.5 0.5NR = Not run

EXAMPLES 96-110

These Examples give the metals and phosphorus content of desalted crudeand effluent water treated at several dosages (10, 15, 50, 100, 500 and1000 ppm based on the crude) for Additive G. The wash water rate for allExamples was 5.5%, and the mix ΔP for all Examples was 12 psig. Mostspecies were removed to the same extent at all dosages. Most of the Na,K, Ca, Fe, Cu, and Ba were removed at 10 ppm and higher. The Ni and Vlevels did not seem to be affected by the treatment. The Si was the onlyelement to be more efficiently removed at higher treatment dosages. TheP was removed to about 25-30% at the various dosages.

In one non-limiting theory, it may be that not all phosphorus speciesare the same. There may be more than one kind of phosphorus speciespresent, and these treatments may only be removing some of them. It maybe that at higher temperatures the additives herein will be moreefficient at removing P compounds. Desalters typically run at about 125to about 150° C., whereas the EDDA tests were run at 100° C. TABLE XIIEx. Sample Identification 96 Raw crude 97 Treat with demulsifier Blend Y@ 10 ppm-v Additive G @ 10 ppm-v Desalter crude 98 Treat withdemulsifier Blend Y @ 10 ppm-v Additive G @ 15 ppm-v Desalter crude 99Treat with demulsifier Blend Y @ 10 ppm-v Additive G @ 50 ppm-v Desaltercrude 100 Treat with demulsifier Blend Y @ 10 ppm-v Additive G @ 100ppm-v Desalter crude 101 Treat with demulsifier Blend Y @ 10 ppm-vAdditive G @ 500 ppm-v Desalter crude 102 Treat with demulsifier Blend Y@ 10 ppm-v Additive G @ 1,000 ppm-v Desalter crude 103 Treat withdemulsifier Blend Y @ 10 ppm-v Lactic acid @ 100 ppm-v Desalter crude104 Treat with demulsifier Blend Y @ 10 ppm-v Additive G @ 10 ppm-vEffluent water 105 Treat with demulsifier Blend Y @ 10 ppm-v Additive G@ 15 ppm-v Effluent water 106 Treat with demulsifier Blend Y @ 10 ppm-vAdditive G @ 50 ppm-v Effluent water 107 Treat with demulsifier Blend Y@ 10 ppm-v Additive G @ 100 ppm-v Effluent water 108 Treat withdemulsifier Blend Y @ 10 ppm-v Additive G @ 500 ppm-v Effluent water 109Treat with demulsifier Blend Y @ 10 ppm-v Additive G @ 1,000 ppm-vEffluent water 110 Treat with demulsifier Blend Y @ 10 ppm-v Lactic acid@ 100 ppm-v Effluent water

TABLE VI ICP EDDA Test Results (ppm - wt/wt), Examples 96-110 Ex. Na KMg Ca Mo Fe Cu Zn Al  96 110 6.2 5.4 30.0 <0.4 22.7 0.5 1.3 1.1  97 0.7<0.4 1.6 0.4 <0.4 0.5 <0.4 0.9 <0.4  98 1.7 <0.4 2.6 0.9 <0.4 0.6 <0.41.1 <0.4  99 1.8 <0.4 2.8 1.1 <0.4 1.6 <0.4 1.1 <0.4 100 0.9 <0.4 1.50.6 <0.4 0.5 <0.4 1.3 <0.4 101 60.5 0.4 2.9 2.6 <0.4 1.2 <0.4 0.9 <0.4102 0.9 <0.4 1.6 0.7 <0.4 0.6 0.4 1.1 <0.4 103 1.0 <0.4 1.6 0.7 <0.4 0.7<0.4 1.0 <0.4 104 1630 87.0 71.4 423 <0.1 47.1 0.8 9.8 1.2 105 1490 69.567.6 388 <0.1 48.8 <0.1 2.7 1.1 106 1370 71.2 65.5 367 <0.1 68.8 0.8 4.51.5 107 1290 64.3 63.0 345 <0.1 74.0 1.0 6.2 1.9 108 1520 78.3 72.2 420<0.1 145 2.6 6.8 7.6 109 1385 67.8 66.3 372 <0.1 149 14.6 10.4 6.8 1101370 72.4 65.0 368 <0.1 77.2 0.6 3.5 2.8 Ex. Ba Be Cd Cr Pb Mn Ni B  965.2 <0.4 <0.4 <0.4 <0.4 <0.4 3.5 <0.4  97 <0.4 <0.4 <0.4 <0.4 <0.4 <0.43.4 2.0  98 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.7 <0.4  99 <0.4 <0.4 <0.4<0.4 <0.4 <0.4 4.0 <0.4 100 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.6 <0.4 101<0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.9 <0.4 102 <0.4 <0.4 <0.4 <0.4 <0.4 <0.43.8 <0.4 103 <0.4 <0.4 <0.4 <0.4 <0.4 <0.4 3.8 <0.4 104 0.5 <0.1 <0.1<0.1 0.3 0.9 0.4 5.6 105 0.5 <0.1 <0.1 <0.1 0.1 0.8 0.2 3.9 106 0.5 <0.1<0.1 <0.1 0.2 0.9 0.2 3.2 107 0.5 <0.1 <0.1 <0.1 0.3 0.9 0.3 2.8 108 0.6<0.1 <0.1 <0.1 0.5 1.2 0.3 3.1 109 0.6 <0.1 <0.1 <0.1 0.8 1.1 0.3 2.8110 0.5 <0.1 <0.1 <0.1 0.2 0.9 0.2 2.7 Ex. Sr Si P S Ti V Sn  96 1.1 1.92.7 NR <0.4 7.9 0.6  97 <0.4 0.6 1.9 NR <0.4 7.5 0.6  98 <0.4 0.7 2.1 NR<0.4 8.3 0.6  99 <0.4 0.8 2.2 NR 1.2 8.8 0.4 100 <0.4 0.5 1.8 NR <0.47.9 <0.4 101 <0.4 1.1 2.2 NR <0.4 8.8 0.4 102 <0.4 0.6 2.0 NR <0.4 8.50.5 103 <0.4 0.7 2.0 NR <0.4 8.3 0.5 104 11.1 1.4 2.1 302 <0.1 <0.1 <0.1105 10.4 1.4 2.2 284 <0.1 <0.1 <0.1 106 9.7 1.5 2.5 286 <0.1 <0.1 <0.1107 9.2 1.4 2.5 268 <0.1 <0.1 <0.1 108 10.9 1.9 4.7 294 <0.1 <0.1 <0.1109 10.0 2.1 5.5 265 <0.1 <0.1 <0.1 110 9.7 1.5 2.8 272 <0.1 <0.1 <0.1

The FIGURE presents a graph showing the partitioning across desalters ofvarious amines and ammonia as a function of pH. The addition ofwater-soluble hydroxyacids of this invention such as glycolic andgluconic acid to the desalter wash water at the use rates specifiedherein will reduce the water's pH to the range of about 3-6.5.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been demonstrated aseffective in transferring metals, e.g. calcium, potassium, phosphorus,etc., and/or amines from crude oil to the aqueous phase in bench scaledesalting testing, as non-limiting examples. However, it will be evidentthat various modifications and changes can be made thereto withoutdeparting from the broader spirit or scope of the invention as set forthin the appended claims. Accordingly, the specification is to be regardedin an illustrative rather than a restrictive sense. For example,specific water-soluble hydroxyacids, and combinations thereof with othermineral acids, other than those specifically exemplified or mentioned,or in different proportions, falling within the claimed parameters, butnot specifically identified or tried in a particular application totransfer metals and/or amines into the aqueous phase, are within thescope of this invention. Similarly, it is expected that the inventivecompositions will find utility as metal and phosphorus transfercompositions for other fluids besides crude oil emulsions.

1. A method of transferring reactive phosphorus species from ahydrocarbon phase to a water phase comprising: adding to an emulsion ofhydrocarbon and water, an effective amount of a composition to transferat least a portion of the reactive phosphorus species from a hydrocarbonphase to a water phase, the composition comprising at least onewater-soluble hydroxyacid selected from the group consisting of glycolicacid, gluconic acid, C₂-C₄ alpha-hydroxy acids, poly-hydroxy carboxylicacids, thioglycolic acid, chloroacetic acid, polymeric forms of theabove hydroxyacids, poly-glycolic esters, glycolate ethers, and ammoniumsalt and alkali metal salts of these hydroxyacids, and mixtures thereof;and resolving the emulsion into hydrocarbon phase and an aqueous phase,where at least a portion of the reactive phosphorus species istransferred to the aqueous phase.
 2. The method of claim 1 where in theadding of the composition, the composition additionally comprises amineral acid.
 3. The method of claim 2 where in the adding of thecomposition, the composition further comprises down to about 1 wt. %water-soluble hydroxyacid; and up to about 20 wt. % mineral acid.
 4. Themethod of claim 2 where the method is practiced in a refinery desaltingprocess and further comprises washing the emulsion with wash water andthe amount of mineral acid is sufficient to lower the pH of the washwater to 6 or below.
 5. The method of claim 1 where in the adding of thecomposition, the water-soluble hydroxyacid is present in the emulsion inan amount ranging from about 1 to about 10,000 ppm.
 6. The method ofclaim 1 where in the adding of the composition, the composition furthercomprises water or alcohol solvent.
 7. The method of claim 1 furthercomprising after adding the composition to the emulsion, heating theemulsion to a temperature above about 180° F. (about 82° C.).
 8. Amethod of transferring reactive phosphorus species from a hydrocarbonphase to a water phase comprising: adding to an emulsion of hydrocarbonand water, an effective amount of a composition to transfer at least aportion of the reactive phosphorus species from a hydrocarbon phase to awater phase, the composition comprising at least one water-solublehydroxyacid selected from the group consisting of glycolic acid,gluconic acid, C₂-C₄ alpha-hydroxy acids, poly-hydroxy carboxylic acids,thioglycolic acid, chloroacetic acid, polymeric forms of the abovehydroxyacids, poly-glycolic esters, glycolate ethers, and ammonium saltand alkali metal salts of these hydroxyacids, and mixtures thereof,where the water-soluble hydroxyacid comprises from about 1 to about 100wt. % of the composition and the composition further comprises a wateror alcohol solvent; and resolving the emulsion into hydrocarbon phaseand an aqueous phase, where at least a portion of the reactivephosphorus species is transferred to the aqueous phase.
 9. The method ofclaim 8 where the method is practiced in a refinery desalting processand further comprises washing the emulsion with wash water and theamount of mineral acid is sufficient to lower the pH of the wash waterto 6 or below.
 10. The method of claim 8 further comprising after addingthe composition to the emulsion, heating the emulsion to a temperatureabove about 180° F. (about 82° C.).
 11. A composition for transferringreactive phosphorus species from a hydrocarbon phase to a water phasecomprising: a water-soluble hydroxyacid selected from the groupconsisting of glycolic acid, gluconic acid, C₂-C₄ alpha-hydroxy acids,poly-hydroxy carboxylic acids, thioglycolic acid, chloroacetic acid,polymeric forms of the above hydroxyacids, poly-glycolic esters,glycolate ethers, and ammonium salt and alkali metal salts of thesehydroxyacids, and mixtures thereof; and a mineral acid.
 12. Thecomposition of claim 11 where the composition additionally comprises atleast one additional component selected from the group consisting of awater or alcohol solvent, a corrosion inhibitor, a demulsifier, a scaleinhibitor, metal chelants, wetting agents and mixtures thereof.
 13. Thecomposition of claim 11 where the composition further comprises: down toabout 1 wt. % water-soluble hydroxyacid; and up to about 20 wt. %mineral acid.
 14. A composition for transferring reactive phosphorusspecies from a hydrocarbon phase to a water phase comprising: awater-soluble hydroxyacid selected from the group consisting of glycolicacid, gluconic acid, C₂-C₄ alpha-hydroxy acids, poly-hydroxy carboxylicacids, thioglycolic acid, chloroacetic acid, polymeric forms of theabove hydroxyacids, poly-glycolic esters, glycolate ethers, and ammoniumsalt and alkali metal salts of these hydroxyacids, and mixtures thereof;and at least one additional component selected from the group consistingof a water or alcohol solvent, a corrosion inhibitor, a demulsifier, ascale inhibitor, metal chelants, wetting agents and mixtures thereof.15. The composition of claim 14 where the water-soluble hydroxyacidcomprises from about 1 to about 85 wt % of the composition.
 16. Atreated hydrocarbon emulsion comprising: a hydrocarbon phase; a waterphase; and a composition for transferring at least a portion of areactive phosphorus species from the hydrocarbon phase to the waterphase comprising a water-soluble hydroxyacid selected from the groupconsisting of glycolic acid, gluconic acid, C₂-C₄ alpha-hydroxy acids,poly-hydroxy carboxylic acids, thioglycolic acid, chloroacetic acid,polymeric forms of the above hydroxyacids, poly-glycolic esters,glycolate ethers, and ammonium salt and alkali metal salts of thesehydroxyacids, and mixtures thereof.
 17. The treated hydrocarbon emulsionof claim 16 where the composition further comprises a mineral acid. 18.The treated hydrocarbon emulsion of claim 17 where the compositionfurther comprises: down to about 1 wt. % water-soluble hydroxyacid; andup to about 20 wt. % mineral acid;
 19. The treated hydrocarbon emulsionof claim 17 further comprising wash water and where the amount ofmineral acid is sufficient to lower the pH of the wash water to 6 orbelow.
 20. The treated hydrocarbon emulsion of claim 16 where thewater-soluble hydroxyacid is present in the emulsion in an amountranging from about 1 to about 10,000 ppm.
 21. The treated hydrocarbonemulsion of claim 16 where the composition further comprises at leastone additional component selected from the group consisting of a wateror alcohol solvent, a corrosion inhibitor, a demulsifier, a scaleinhibitor, metal chelants, wetting agents and mixtures thereof.
 22. Thetreated hydrocarbon emulsion of claim 16 where the hydrocarbon componentcontains more than 3 ppm of a reactive phosphorus species.